UNITED STATES
SECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549



FORM 10-Q

ý

Quarterly Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the quarterly period ended September 30, 2015Oro

Transition Report Pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934 for the transition period
from                    to


Commission File Number: 0-06910



TEL OFFSHORE TRUST(Exact name of registrant as specified in its charter)

Texas(State or other jurisdiction of
incorporation or organization)

76-6004064(I.R.S. Employer
Identification No.)The Bank of New York Mellon Trust Company, N.A.
919 Congress Avenue
Austin, Texas(Address of principal executive offices)

78701(Zip Code)


(512) 236-6599(Registrant's telephone number, including area code)

Indicate
by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the
preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes ý    No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be
submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the
registrant was required to submit and post such files). Yes o    No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the
definitions of "large accelerated filer," "accelerated filer" and "smaller reporting company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer o

Accelerated filer o

Non-accelerated filer ý (Do not check if a
smaller reporting company)

Smaller reporting company o


Indicate
by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes o    No ý

As of November 12, 2015, 4,751,510 Units of Beneficial Interest in TEL Offshore Trust were outstanding.





---





NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q (this "Form 10-Q") includes "forward-looking statements" within the meaning of
Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended. All statements other than statements of historical facts
included in this Form 10-Q, including without limitation, statements under "Trustee's Discussion and Analysis of Financial Condition and Results of Operations" in Item 2 of Part I
and elsewhere herein regarding the financial position, production and reserve growth, and other plans and objectives are forward-looking statements. Forward-looking statements are generally
accompanied by words such as "estimate," "project," "predict," "believe," "expect," "anticipate," "could," "may," "should," "intend" or other words that convey the uncertainty of future events or
outcomes. These forward-looking statements are based on current expectations and assumptions about future events. Although Chevron USA, Inc., the Managing General Partner of the TEL Offshore
Trust Partnership, has advised the Trust that the Managing General Partner believes that the expectations reflected in the forward-looking statements contained herein are reasonable, no assurance can
be given that such expectations will prove to have been correct. Important factors that could cause actual results to differ materially from expectations are disclosed in the risk factors discussed in
Item 1A of Part I of the Trust's Annual Report on Form 10-K for the year ended December 31, 2014 (the "2014 10-K") and such other factors as may be set forth from time to
time in the Trust's filings with the Securities and Exchange Commission. All subsequent written and oral forward-looking statements attributable to the Managing General Partner or the Trust or persons
acting on behalf of the Managing General Partner or the Trust are expressly qualified in their entirety by such factors. The Trust assumes no obligation, and disclaims any duty, to update these
forward-looking statements.

---





PART IFINANCIAL INFORMATION

Item 1.    Condensed Financial Statements.

TEL OFFSHORE TRUST  CONDENSED STATEMENTS OF ASSETS, LIABILITIES AND TRUST CORPUS (UNAUDITED)

September 30,
2015

December 31,
2014AssetsCash and cash equivalents

$
487,276

$
243,923Net overriding royalty interest in oil and gas properties, net of accumulated amortization of $28,268,761 and $28,255,605, respectively


10,257


12,050​
​
​
​
​
​
​
​Total assets

$
497,533

$
255,973​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​Liabilities and Trust CorpusDistribution payable to Unit holders

$


$
Cash advances


0


116,277Note payable


1,056,885


363,000Reserve for future Trust expenses





Trust corpus (4,751,510 Units of beneficial interest authorized and outstanding)


(559,352
)

(223,304
)​
​
​
​
​
​
​
​Total liabilities and Trust corpus

$
497,533

$
255,973​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​


CONDENSED STATEMENTS OF DISTRIBUTABLE INCOME (UNAUDITED)

Three Months Ended
September 30,

Nine Months Ended
September 30,2015

2014

2015

2014Royalty income

$


$


$


$
Interest income











​
​
​
​
​
​
​
​
​
​
​
​
​
​








Decrease in reserve for future Trust expenses





187,957





853,918Proceeds from Note and cash advances used for Trust expenses


96,765





334,255


General and administrative expenses


(96,765
)

(187,957
)

(334,255
)

(853,918
)​
​
​
​
​
​
​
​
​
​
​
​
​
​Distributable income











​
​
​
​
​
​
​
​
​
​
​
​
​
​Distributable income per Unit (basic and diluted (4,751,510 Units))

$
.000000

$
.000000

$
.000000

$
.000000​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​Distributions per Unit (4,751,510 Units)

$
.000000

$
.000000

$
.000000

$
.000000​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​


The
accompanying notes are an integral part of these condensed financial statements.

1

---





CONDENSED STATEMENTS OF CHANGES IN TRUST CORPUS (UNAUDITED)

Three Months Ended
September 30,

Nine Months Ended
September 30,2015

2014

2015

2014Trust corpus, beginning of period

$
(462,050
)
$
13,500

$
(223,304
)
$
14,515Distributable income











Distribution payable to Unit holders











Proceeds from Note and cash advances used for Trust expenses


(96,765
)




(334,255
)

Amortization of net overriding royalty interest


(537
)

(664
)

(1,793
)

(1,679
)​
​
​
​
​
​
​
​
​
​
​
​
​
​Trust corpus, end of period

$
(559,352
)
$
12,836

$
(559,352
)
$
12,836​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​




The accompanying notes are an integral part of these condensed financial statements.

2

---





TEL OFFSHORE TRUST        NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED)

(1) Trust Organization

Tenneco Offshore Company, Inc. ("Tenneco Offshore") created the TEL Offshore Trust ("Trust") effective January 1, 1983, pursuant to the Plan of Dissolution ("Plan") approved by
Tenneco Offshore's stockholders on December 22, 1982. In accordance with the Plan, the TEL Offshore Trust Partnership ("Partnership") was formed in which the Trust owns a 99.99% interest and
Tenneco Oil Company initially owned a .01% interest. In general, the Plan was effected by transferring an overriding royalty interest equivalent to a 25% net profits interest (the "Original Royalty")
in the oil and gas properties (the "Royalty Properties") of Tenneco Exploration, Ltd. located offshore Louisiana to the Partnership and issuing certificates evidencing units of beneficial interest in
the Trust ("Units") in liquidation and cancellation of Tenneco Offshore's common stock. The term "Original Royalty" shall refer to the initial 25% net profits interest in the Royalty Properties and
the term "Royalty" shall refer to the applicable net profits interest held from time to time by the Partnership following the Royalty Sales (as defined in Note 3 below).

On
January 14, 1983, Tenneco Offshore distributed Units to holders of Tenneco Offshore's common stock on the basis of one Unit for each common share owned on such date.

The
terms of the Trust Agreement, dated January 1, 1983 (as amended, the "Trust Agreement"), provide, among other things, that:



3

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(1) Trust Organization (Continued)

On
October 27, 2011, the Partnership sold 20% of the Original Royalty (or 5% of 8/8ths) for gross proceeds of $1,600,000. See Note 3.

On
October 31, 2013, the Partnership consummated the sale of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths) and following such sale now holds 60% of the
Original Royalty interest (or 15% of 8/8ths). See Note 3.

The
Trust is currently administered by The Bank of New York Mellon Trust Company, N.A. (the "Corporate Trustee"), which succeeded JPMorgan Chase Bank, N.A. as the corporate
trustee, effective October 2, 2006 pursuant to an agreement under which The Bank of New York acquired substantially all of the corporate trust business of JPMorgan Chase (formerly known
as The Chase Manhattan Bank), and Gary C. Evans, Thomas H. Owen, Jr., and Jeffrey S. Swanson (the "Individual Trustees"), as trustees (collectively, the "Trustees").

The
Trustees, including the Corporate Trustee, have no authority over, have not evaluated and make no statement concerning, the internal control over financial reporting of any of the
owner or owners of the Royalty Properties (the "Working Interest Owners").

(2) Basis of Accounting and Going Concern

The accompanying unaudited financial information has been prepared by the Corporate Trustee. The accompanying financial information is prepared on a comprehensive basis of accounting
other than accounting principles generally accepted in the United States of America ("GAAP"). The Trustees believe that the information furnished reflects all adjustments that are, in the opinion of
the Trustees, necessary for a fair presentation of the results for the interim periods presented. Such adjustments are of a normal and recurring nature. The financial information should be read in
conjunction with the financial statements and notes thereto included in the Trust's Annual Report on Form 10-K for the year ended December 31, 2014.

Overriding Royalty Interest.The Trust uses the modified cash basis of accounting to report Trust receipts from the overriding royalty
and payments
of expenses incurred. The actual cash distributions to the
Trust are made based on the terms of the conveyance that created the Trust's overriding royalty interest. The overriding royalty interest entitles the Trust to receive revenues (oil, gas and natural
gas liquid sales) less expenses (the amount by which all royalties, lease operating expenses including well workover costs, production and property taxes, post-production costs including plugging and
abandonment, and producing overhead of the underlying properties) multiplied by the Partnership's interest in the Original Royalty. The Original Royalty initially represented a 25% net profits
interest but after the Royalty Sales, the Royalty now represents a 15% net profits interest. Actual cash receipts may vary due to timing delays of cash receipts from the property operators or
purchasers and due to wellhead and pipeline volume balancing agreements or practices.

4

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

Modified Cash Basis of Accounting.The condensed financial statements of the Trust, as prepared on a modified cash basis, reflect the
Trust's assets,
liabilities, Trust corpus, earnings and distributions, as follows:



This
manner of reporting income and expenses is considered to be the most meaningful because the quarterly distributions to Unit holders are based on net cash receipts received from the
Working Interest Owners. The condensed financial statements of the Trust differ from condensed financial statements prepared in accordance with GAAP, because, under such principles, Royalty income and
Trust general and administrative expenses for a quarter would be recognized on an accrual basis. In addition, amortization of the net overriding royalty interest, calculated on a units-of-production
basis, is charged directly to Trust corpus since such amount does not affect distributable income. This comprehensive basis of accounting other than GAAP corresponds to the accounting permitted for
royalty trusts by the U.S. Securities and Exchange Commission, as specified by Staff Accounting Bulletin Topic 12:E,Financial Statements of Royalty
Trusts.

Oil and Gas Reserves.The proved oil and gas reserves for the underlying properties are estimated by independent petroleum engineers.
Reserve
engineering is a subjective process that is dependent upon the quality of available data and the interpretation thereof. Estimates by different engineers often vary, sometimes significantly. In
addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, as well as economic factors such as changes in product prices and production
costs, may justify revision of such estimates. Accordingly, oil and gas

5

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

quantities
ultimately recovered and the timing of production may be substantially different from estimates.

The
standardized measure of discounted future net cash flows is prepared using assumptions made pursuant to FASB and SEC guidelines. Such assumptions include using average fiscal-year
oil and gas prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month reporting period) and year-end costs for estimated future
production expenditures. Discounted future net cash flows are calculated using a 10% discount rate. Changes in any of these assumptions could have a significant impact on the standardized measure. The
standardized measure does not necessarily result in an estimate of the current fair market value of proved reserves.

Amortization of Overriding Royalty Interest.The Trust amortizes the investment in overriding royalty interest using the
units-of-production method.
The Trust's rate of recording amortization is dependent upon the estimates of total proved reserves, which incorporates various assumptions and future projections. If the estimates of total proved
reserves decline significantly, the rate at which the Trust records amortization expense would increase, reducing Trust corpus. Such a decline in reserves may result from lower commodity prices, which
may make it uneconomic to produce from higher cost fields. The Trust is unable to predict changes in reserve quantity estimates as such quantities are dependent on future economic and operational
conditions.

Impairment of Investment in Overriding Royalty Interest.The Trust reviews overriding royalty interests in oil and gas properties for
possible
impairment whenever events or circumstances indicate the carrying amount of the asset may not be recoverable. If there is an indication of impairment, the Trust prepares an estimate of future cash
flows (undiscounted and without interest charges) expected to result from the use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an
impairment loss is recognized to write down the asset to its estimated fair value. Preparation of estimated expected future cash flows is inherently subjective and is based on the Corporate Trustee's
best estimate of assumptions concerning expected future conditions. There were no write downs taken in the three months ended September 30, 2015.

Cash and Cash Equivalents.Cash and cash equivalents include all highly liquid short-term investments with original maturities of three
months or
less.

Reserve for future Trust expenses.Represents cash reserves for future Trust expenses established by the Trustee. The changes in
reserves for future
Trust expenses includes both changes of amounts deemed necessary by the Trustees and related distributions, as well as amounts paid from the reserve during periods when the Trust has insufficient
income to pay Trust expenses. See Note 6.

Proceeds from Sale of Overriding Royalty.The Trust records proceeds from the sale of overriding royalty interests when received.

6

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(2) Basis of Accounting and Going Concern (Continued)

Special Cost Escrow account.The Special Cost Escrow account (see Note 5) is established for future costs to be incurred to plug
and abandon
wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. The funds held in the Special
Cost Escrow account are not reflected in the condensed financial statements of the Trust. However, funds deposited to or released from the Special Cost Escrow account are included in Royalty income.

Use of Estimates.The preparation of financial statements requires the Trustees to make use of estimates and assumptions that affect
amounts reported
in the condensed financial statements as well as certain disclosures. Actual results could differ from those estimates.

Recent Accounting Pronouncements.There were no accounting pronouncements issued during the three months ended September 30, 2015,
applicable
to the Trust or its condensed financial statements.

Going Concern.The accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going
concern. Financial
statements prepared on the going concern basis assume the realization of assets and the settlement of liabilities in the normal course of business. The Trust received $787 in Royalty income in October
of 2015 and except for this amount, the Trust has received no other distributions since the fourth quarter of 2008. The lack of sufficient Net Proceeds to make distributions in the foreseeable future
as discussed in Note 4 and the inability to maintain adequate cash reserves raise substantial doubt about the Trust's ability to continue as a going concern. Certain potential alternatives
available to the Trustees are described in Note 6. The condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty.

(3) Net Overriding Royalty Interest

The Original Royalty entitled the Trust to its share (99.99%) of 25% of the Net Proceeds attributable to the Royalty Properties. The Conveyance, dated January 1, 1983, provides
that the Working Interest Owners will calculate, for each period of three months commencing the first day of February, May, August and November, an amount equal to 25% of the Net Proceeds from their
oil and gas properties for the period. Generally, "Net Proceeds" means the amount received by the Working Interest Owners from the sale of minerals from the Royalty Properties less operating and
capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the Special Cost Escrow
account. The Special Cost Escrow account is established for the future costs to be incurred to plug and abandon
wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not include
amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future
delivery of gas.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths). The

7

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(3) Net Overriding Royalty Interest (Continued)

2011
Royalty Sale was made to RNR Production, Land and Cattle Company, Inc. ("RNR Production") on October 27, 2011, though the assignment was effective as of August 1, 2011. Refer to
Note 6 for further discussion of the 2011 Royalty Sale.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale" and, together with the 2011 Royalty Sale,
the "Royalty Sales") of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths). The 2013 Royalty Sale to RNR Production closed on October 31, 2013, though the assignment was
effective as of August 1, 2013. Refer to Note 6 for further discussion of the 2013 Royalty Sale.

Following
the Royalty Sales, the Partnership has retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the future only 15% of the Net Proceeds when
there are sufficient Net Proceeds for distribution on the Partnership's Royalty.

On
the last business day of each calendar quarter prior to August 1, 2011, the Working Interest Owners were to pay to the Partnership 25% of the Net Proceeds for the immediately
preceding Quarterly Period; however, (i) as a result of the 2011 Royalty Sale, on the last business day of each calendar quarter after August 1, 2011 and prior to August 1, 2013,
the Working Interest Owners were to pay to the Partnership 20% of the Net Proceeds for the immediately preceding Quarterly Period and (ii) as a result of the 2013 Royalty Sale, on the last
business day of each calendar quarter after August 1, 2013, the Working Interest Owners are to pay to the Partnership 15% of the Net Proceeds for the immediately preceding Quarterly Period. A
Quarterly Period is each period of three months commencing on the first day of February, May, August and November. In turn, the Partnership distributes funds to its partners on the last business day
of each calendar quarter. Cash distributions from the Trust, if any, are made in January, April, July and October of each year, and are payable to
Unit holders of record as of the last business day of each calendar quarter. Thus, any cash conveyed to the Trust from the Partnership during the quarter ended September 30, 2015 would
substantially represent the revenues and expenses from the Royalty Properties from May 2015 through July 2015. Similarly, any cash conveyed to the Trust from the Partnership during the quarter ended
September 30, 2014 would substantially represent the revenues and expenses from the Royalty Properties from May 2014 through July 2014. There was no cash conveyed to the Trust from the
Partnership pursuant to its overriding royalty interest in the Royalty Properties from either May 2015 through July 2015 or May 2014 through July 2014. In October 2015, the Trust received, pursuant to
the Partnership's overriding royalty interest in Eugene Island 342, the amount of $787 for the period August 2015 through October 2015. The financial and operating information included in this
Form 10-Q for the three and nine months ended September 30, 2015 and September 30, 2014 represents financial and operating information with respect to the Royalty Properties for
the immediately preceding months of November, December, January, February, March, April, May, June and July. Income received pursuant to the Partnership's overriding royalty interest is recorded by
the Trust on a cash basis, when it is received by the Trust from the Partnership.

8

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(4) Distributions to Unit Holders

In accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves
established for the payment of contingent or future obligations of the Trust, are distributed quarterly to the Unit holders. These distributions are referred to as "distributable income." The amounts
distributed are determined on a quarterly basis and are payable to Unit holders of record as of the last business day of each
calendar quarter. However, cash distributions are made in January, April, July and October and include interest earned from the quarterly record date to the date of distribution.

Production
ceased at Eugene Island 339 and Ship Shoal 182 and 183 following damages inflicted by Hurricane Ike in September 2008. Future Net Proceeds may take into account the Trust's
share of project costs and other related expenditures that are not covered by insurance of the operator of the Royalty Properties. On December 19, 2008, the Trust announced its fourth quarter
distribution of approximately $0.7 million, which was paid on January 9, 2009. The funds available for the fourth quarter distribution were severely negatively impacted by lower
production as a result of shutdowns and damage to producing assets because of Hurricane Ike. On March 25, 2009, the Trust announced that there would be no trust distribution for the first
quarter of 2009, and the Trust has not made a distribution since January 9, 2009.

While
oil and gas production at Ship Shoal 182 and 183, Eugene Island 339, South Timbalier 36/37 and Eugene Island 342 has been partially restored, there are not likely to be
sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly distribution to Unit holders for the foreseeable future. As a result of the damage inflicted
by Hurricane Ike, Net Proceeds will continue to be severely impacted by reduced production. Although the Trust received a payment of $787 from the operator of Eugene Island 342 in October of 2015,
there can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions
will be made. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the aggregate cost to the Original Royalty to plug and abandon the wells, remove
and abandon platforms and infrastructure and remediate the surface subject to the overriding royalty interest on Eugene Island 339 was approximately $19.8 million and that no further expenses
of this nature relating to prior hurricane damage are expected to be incurred. If development and production costs of the Royalty Properties owned by an operator exceed the proceeds of production from
the Royalty Properties owned by such operator, the Trust will not receive Net Proceeds from such operator until future proceeds from production from the Royalty Properties owned by such operator
exceed the total of the excess costs plus accrued interest. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds from Chevron, as the operator of the Royalty
Properties, since December 2008. As of July 31, 2015, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of production
from the Royalty Properties by approximately $1.7 million, net to the entire Original Royalty ($1.0 million applicable to the Trust).

9

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(4) Distributions to Unit Holders (Continued)

On
May 13, 2015, Chevron conveyed certain oil and gas properties to Fieldwood Energy Offshore LLC ("Fieldwood"), including Chevron's interest in Eugene Island 342 that was
subject to the Royalty. Any Net Proceeds from Fieldwood attributable to Eugene Island 342 are not subject to offset by Chevron against the undistributed net loss carry forward attributable to the
Royalty Properties held by Chevron. Consequently, during October 2015 the Trust received Royalty income of $787 attributable to Eugene Island 342. However, in accordance with the Trust Agreement, no
distributions will be made by the Trust to the Unit holders until the Trust's indebtedness (as described in Note 10) is paid in full.

For
the three months ended September 30, 2015, the Trust had undistributed net income of $195,946, representing the Trust's portion of the aggregate undistributed net income of
$1,306,304 associated with the Royalty Properties for the three months ended September 30, 2015. For the nine months ended September 30, 2015, the Trust had undistributed net income of
$639,183, representing the Trust's portion of the aggregate undistributed net income of $4,261,214 associated with the Royalty Properties for the nine months ended September 30, 2015.
Undistributed net income represents positive Net Proceeds generated during the respective period, but not distributed by the Working Interest Owners.

The
Trust's portion of the cumulative undistributed net loss associated with the Royalty Properties was $1.0 million as of July 31, 2015. Undistributed net loss represents
the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried
forward and offset, in future periods, by positive proceeds earned by the related Working Interests Owner(s). The Trust will not receive Net Proceeds attributable to the Royalty Properties (excluding
Eugene Island 342) until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. In addition, the Trust will not make any distributions to the Unit
holders until any indebtedness of the Trust, such as the 2015 Note (as defined in Note 10 below) is repaid in full. In addition, to the extent Net Proceeds are otherwise distributable to the
Trust, the amount of such distribution will be significantly reduced by deposits to the Special Cost Escrow account until such Special Cost Escrow account is replenished with funds in an amount
determined by the Working Interest Owners.

On
September 30, 2015, the Trust issued a press release announcing that there would be no trust distribution for the third quarter of 2015 for the unit holders of record on
September 30, 2015.

(5) Special Cost Escrow Account

The Special Cost Escrow is an account of the Working Interest Owners, and it is described herein for informational purposes only. The Conveyance provides for reserving funds for
estimated future "Special Costs" of plugging and abandoning wells, dismantling platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling
projects and other capital expenditures on the Royalty Properties. As provided in the Conveyance, the amount of funds to be reserved is determined based on certain factors, including estimates of
aggregate future production costs, aggregate future Special Costs, aggregate future net revenues and actual current net proceeds.

10

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(5) Special Cost Escrow Account (Continued)

Deposits
into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account is herein referred to as the "Special Cost
Escrow" account. As of September 30, 2015, approximately $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed
financial statements of the Trust. Special Cost Escrow account funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs.
Special Costs that have been paid are no longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost
Escrow account is less than 125% of estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues
pursuant to a formula contained in the Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs
have been incurred. Amounts in the Special Cost Escrow account will also be released when the balance in such account exceeds 125% of future Special Costs.

During
the nine months ended September 30, 2015 and during the year ended December 31, 2014, there were no funds released from or deposited into the Special Cost Escrow
account.

RNR
Production was the purchaser of the partial interests in the overriding royalty interest sold pursuant to the Royalty Sales and now holds 40% of the Original Royalty (or 10% of
8/8ths) and 40% of the Partnership's rights and obligations with respect to the Special Cost Escrow, which were assigned in connection with the Royalty Sales.

Deposits
to the Special Cost Escrow Account will be required in future periods in connection with other production costs, other abandonment costs, other capital expenditures and changes
in the estimates and factors described above. Such deposits are expected to result in a significant reduction in Royalty income in the periods in which such deposits are made.

(6) Reserve For Future Trust Expenses

Historically, the Trust generally maintained a cash reserve, equal to approximately three times the average annual expenses of the Trust during each of the then past three years, to
provide for future administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in
September 2008, the Trust has not received sufficient Net Proceeds to maintain the reserve at such level. As of September 30, 2015 and December 31, 2014 the reserve amount was $0.

During
October 2015, the Trust received $787 in distributions from the operator of Eugene Island 342; however, the Trust has received no other distributions since December 2008. There
can be no assurance by Chevron or anyone else as to the actual timing for any future distributions to the Partnership from the Royalty, and there is no guarantee that any further distributions will be
made. Because of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay

11

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses (Continued)

expenses
on a current basis and as described below, the Trust has been required to borrow funds and to cause the Partnership to sell part of the Original Royalty in order to pay Trust expenses. As of
September 30, 2015, including the proceeds from the 2015 Note (as defined below), the Trust's available cash was approximately $487,276. Based upon currently estimated expenditures, inclusive
of the costs and expenses relating to the Probate Proceeding (as defined below), it is anticipated that the Trust's available cash will be depleted during the first quarter of 2016. Following the
depletion of the Trust's available cash, it is anticipated that the Trust will continue to fund the costs and expenses of the Probate Proceeding through additional loans and cash advances from The
Bank of New York Mellon. However, The Bank of New York Mellon will continue to evaluate the Probate Proceeding and the costs and expenses associated therewith. It is further anticipated
that any such loans and cash advances will be repaid from any proceeds received by the Trust, including any proceeds received upon any sale of the remaining Royalty and will therefore reduce the cash
available for distribution to the Unit holders.

Pursuant
to the terms of the Trust Agreement, the Trustees are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that
cash on hand is not sufficient to pay the liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders
until the indebtedness created by such borrowings has been paid in full. As discussed in Note 10, the Trustees have borrowed, and may in the future borrow, funds of which a portion were, or may
be, used to pay for Trust expenses.

The
Trust Agreement further provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the 2011 Royalty Sale, which generated $1,600,000 in gross proceeds and
occurred as
part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,485,851,
representing 99.99% of the net proceeds from the sale of $1,486,000. The Trust used such net proceeds solely for the payment of expenses of the Trust.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the 2013 Royalty Sale, which generated $1,200,000 in gross proceeds and
occurred as part of a formal auction process for the Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of
approximately $1,151,885, representing 99.99% of the net proceeds from the sale of $1,152,000. The Trust used a portion of the net proceeds received in October 2013 to repay the Trust's indebtedness
under a previous note payable

12

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(6) Reserve For Future Trust Expenses (Continued)

to
The Bank of New York Mellon and used the remaining net proceeds solely for the payment of expenses of the Trust.

In
September 2012, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of the third quarter of 2012, until a date to be determined in the
future by the Trustees. As of December 31, 2013, the amount of such fees was approximately $339,414. The suspended fees were paid in full by the Trust in January 2014 and are included within
general and administrative expenses for the nine months ended September 30, 2014.

In
March 2014, the Trustees again unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the
future by the Trustees. As of September 30, 2015, the amount of such fees was approximately $414,918 in the aggregate. Such suspended fees will be recorded as an expense of the Trust when
invoiced by the Trustees and paid.

On
July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of Travis County, Texas (the "Court"). The
Petition requests the Court to modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow the Trustees, as necessary to fulfill the purposes
of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of the Trust, (b) exercise their rights to
dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding (the "Probate Proceeding") are to permit the Trustees to direct
the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Unit holders; and, to, thereafter terminate the
Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed an attorney ad litem to represent any Unit holders that were not
personally served. The Court appointed attorney ad litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of the Royalty Interests, and
(2) an accounting of the general and administrative expenses of the Trust from 2008 through the present. The trial is currently set for January 15, 2016; however, it is possible that the
Counterclaim filed by the attorney ad litem could result in a delay. There can be no assurances whether the Court will grant the requested relief and, if such relief is granted, when such actions will
be completed.

(7) Federal Income Tax Matters

The IRS has ruled that the Trust is a grantor trust and that the Partnership is a partnership for federal income tax purposes. Thus, the Trust will incur no federal income tax liability
and each Unit holder will be treated as owning an interest in the Partnership.

(8) Commitments and Contingencies

The Managing General Partner of the Partnership has advised the Trust that, although Chevron believes that it is in general compliance with applicable health, safety and environmental
laws and

13

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(8) Commitments and Contingencies (Continued)

regulations
that have taken effect at the federal, state and local levels, costs may be incurred to comply with current and proposed environmental legislation that could result in increased operating
expenses on the Royalty Properties.

(9) Related Party Transactions

Each of the Working Interest Owners owns interests, for its own account, in leases that are in the same area as leases in which the Partnership has acquired or may acquire an interest.
Such relationships may give rise to potential conflicts of interests in, among other things, the operation of such leases and in the acquisition and operation of any drainage leases acquired by a
Working Interest Owner for its own account. Additionally, the Working Interest Owners and their affiliates are not prohibited from purchasing oil and gas produced from or attributable to any leases in
which the Partnership has an interest.

Crude
oil sales from Chevron Corporation accounted for 100% of crude oil revenues from the Royalty Properties for the three and nine months ended September 30, 2015 and 2014.
Sales to Chevron Corporation accounted for 100% of total gas revenues from the Royalty Properties during the three and nine months ended September 30, 2015 and 2014.

The
Trust's share of Royalty income was reduced by approximately $13,891 and $23,728 for each of the three months ended September 30, 2015 and September 30, 2014,
respectively, and $43,457 and $108,108 for each of the nine months ended September 30, 2015 and 2014, respectively, for management fees paid to the Working Interest Owners as reimbursement for
expenses incurred by them on behalf of the Trust. Such management fees were calculated as 3% of the Trust's share of the sum of revenues, production expenses and capital expenditures attributable to
the Royalty Properties in each of the periods above.

(10) Notes Payable

On October 1, 2014, The Bank of New York Mellon made an advance to the Trust in the amount of $363,000, and The Bank of New York Mellon Trust Company, N.A., in its
capacity as corporate trustee, as the borrower, entered into a Demand Promissory Note (the "2014 Note") with The Bank of New York Mellon, as lender ("BONYM"), relating to the unsecured $363,000
advance. The 2014 Note provided for interest at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of the 2014 Note, all amounts outstanding under the 2014 Note were scheduled to be
due and payable in cash on the earliest to occur of (i) the date written demand for payment is made by BONYM or (ii) December 31, 2015. The Trust could prepay any outstanding
principal and accrued and unpaid interest under the 2014 Note, in whole or in part, at any time without penalty. In addition to the 2014 Note, through September 25, 2015, BONYM made additional
cash advances in the amount of $209,885 to the Trust for the payment of its liabilities and expenses, primarily in connection with the Probate Proceeding.

14

---



TEL OFFSHORE TRUST

NOTES TO CONDENSED FINANCIAL STATEMENTS (UNAUDITED) (Continued)

(10) Notes Payable (Continued)

On
September 25, 2015, BONYM made an additional advance to the Trust in the amount of $484,000, and The Bank of New York Mellon Trust Company, N.A., in its capacity as
corporate trustee for the Trust, as the borrower, has entered into a Renewal Demand Promissory Note (the "2015 Note") with BONYM, in the original principal amount of $1,056,885 relating to
(i) the unsecured $484,000 advance, (ii) the renewal and extension of the indebtedness originally evidenced by the 2014 Note in the original principal amount of $363,000, and
(iii) previous advances in the amount of $209,885 made by BONYM on behalf of the Trust. The 2015 Note bears interest at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of
the 2015 Note, all amounts outstanding under the 2015 Note, including
accrued and unpaid interest, will be due and payable in cash on the earliest to occur of (i) the date written demand for payment is made by BONYM or (ii) December 31, 2016. In
addition, the accrued and unpaid interest remaining due from the 2014 Note in the amount of $1,790 is due and payable concurrently with the payment of the 2015 Note. The Trust may prepay any
outstanding principal and accrued and unpaid interest under the 2015 Note, in whole or in part, at any time without penalty.

15

---





Item 2.    Trustee's Discussion and Analysis of Financial Condition and Results of Operations.

Overview

The TEL Offshore Trust, which we refer to herein as the "Trust," was created under the laws of the State of Texas in 1983 and maintains
its offices at the office of The Bank of New York Mellon Trust Company, N.A., whom we refer to as the "Corporate Trustee," 919 Congress Avenue, Suite 500, Austin, Texas 78701. The
telephone number of the Corporate Trustee is (512) 236-6599. Gary C. Evans, Thomas H. Owen, Jr. and Jeffrey S. Swanson serve as individual trustees of the Trust and are
referred to herein as the "Individual Trustees." The Individual Trustees and the Corporate Trustee may be referred to hereinafter collectively as the "Trustees."

The
Corporate Trustee does not maintain a website for filings by the Trust with the U.S. Securities and Exchange Commission, which we refer to herein as the "SEC." Electronic filings by
the Trust with the
SEC are available free of charge through the SEC's website at www.sec.gov. The Trust will also provide paper copies of its recent filing free upon request to the Corporate Trustee.

The
principal asset of the Trust consists of a 99.99% interest in the TEL Offshore Trust Partnership, which we refer to herein as the "Partnership." Chevron U.S.A., Inc., or "Chevron,"
owns the remaining .01% interest in the Partnership and is the Managing General Partner of the Partnership. Until October 27, 2011, the Partnership owned 100% of an overriding royalty interest
equivalent to a 25% net profits interest (the "Original Royalty"), in certain oil and gas properties, which we refer to herein as the "Royalty Properties," located offshore Louisiana. The term
"Original Royalty" shall refer to the initial 25% net profits interest in the Royalty Properties and the term "Royalty" shall refer to the applicable net profits interest held from time to time by the
Partnership following the Royalty Sales (as defined below).

Liquidity and Capital Resources

The Trust's primary source of liquidity and capital is the Royalty income received from its share of the Net Proceeds from the Royalty
Properties. Generally, "Net Proceeds" means the amounts received by the owner or owners of the Royalty Properties (the "Working Interest Owners") from the sale of minerals from the Royalty Properties
less operating and capital costs incurred, management fees and expense reimbursements owing to the Managing General Partner of the Partnership, applicable taxes other than income taxes, and the
Special Cost Escrow account. The Special Cost Escrow account, as more fully detailed in Note 5 to the condensed financial statements, was established for the future costs to be incurred to plug
and abandon wells, dismantle and remove platforms, pipelines and other production facilities, and for the estimated amount of future capital expenditures on the Royalty Properties. Net Proceeds do not
include amounts received by the Working Interest Owners as advance gas payments, "take-or-pay" payments or similar payments unless and until such payments are extinguished or repaid through the future
delivery of gas.

Total
future net revenues attributable to the Partnership's interest in the Royalty were estimated at $7.3 million as of October 31, 2014. Revenue values in the reserve
report were estimated using the initial costs provided by Chevron and the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended
October 31, 2014. These unweighted average prices were $98.42 per barrel of oil and $4.29 per Mcf of natural gas. The prices for oil and natural gas have declined significantly since
October 31, 2014, and it is anticipated that the lower oil and natural

16

---



gas
prices over the 12-month period ended October 31, 2015 will result in a reduction in the total future net revenues attributable to the Partnership's interest in the Royalty as of
October 31, 2015.

During
October 2015, the Trust received $787 in distributions from the Working Interest Owner with respect to Eugene Island 342; however, the Trust has received no other distribution of
Net Proceeds since December 2008. The recent payment to the Trust attributable to Eugene Island 342 was nominal and it is anticipated that any such future distributions attributable to Eugene Island
342 will continue to be nominal in amount. Consequently, there are not likely to be sufficient Net Proceeds from the Royalty Properties for the Trust to make a regularly scheduled quarterly
distribution to Unit holders for the foreseeable future.

Because
of the lack of Net Proceeds, the Trust has in the past not had sufficient cash flow to pay expenses on a current basis and as described below, the Trust has been required to
borrow funds and to cause the Partnership to sell part of the Original Royalty in order to pay Trust expenses. As of September 30, 2015, including the proceeds from the 2015 Note (as herein
defined) and the previous cash advances from The Bank of New York Mellon ("BONYM") included in the principal amount of the 2015 Note, the Trust's available cash was approximately $487,276.
Based upon currently estimated expenditures, inclusive of the costs and expenses relating to the Probate Proceeding (as defined below), it is anticipated that the Trust's available cash will be
depleted during the first quarter of 2016. In light of the continuing expenses of the Trust and the lack of any distributions and any assurances as to the actual timing of any future distributions,
the Trustees have considered the alternatives available to the Trust to obtain funds or to reduce the ongoing costs and expenses of the Trust and after evaluating the alternatives available to the
Trust, the Trustees elected to institute the Probate Proceeding described below.

The
Trust Agreement provides that, if necessary to provide for the payment of specific liabilities of the Trust then due, the Trustees may without a vote of the Unit holders
(a) sell all or a portion of the Trust's interest in the Partnership or any other assets of the Trust for such cash consideration as the Trustees shall deem appropriate, (b) exercise
their rights under the Partnership Agreement to dissolve the Partnership, or (c) cause a sale by the Partnership of the overriding royalty interest owned by the Partnership. Additionally, the
Trustees, on behalf of the Trust, are authorized to borrow funds, and pledge the assets of the Trust to secure payments of such borrowings, in the event that cash on hand in not sufficient to pay the
liabilities of the Trust. In the event that the Trustees borrow funds to pay the liabilities of the Trust, no distributions will be made to the Unit holders until the indebtedness created by such
borrowings has been paid in full.

On
October 27, 2011, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2011 Royalty Sale") of 20% of the Original Royalty (or 5% of
8/8ths), which generated $1,600,000 in gross proceeds and occurred as part of a formal auction process for the Partnership's overriding royalty interest in the Royalty Properties. The Trust received
from the Partnership a distribution of approximately $1,485,581, representing 99.99% of the net proceeds from the sale of $1,486,000. The 2011 Royalty Sale was made to RNR Production, Land and Cattle
Company, Inc. ("RNR Production") on October 27, 2011, though the assignment was effective as of August 1, 2011.

In
September 2012, the Trustees unanimously determined to suspend future payments of fees to the Trustees effective as of the third quarter of 2012, until a date to be determined in the
future by the Trustees. As of December 31, 2013, the amount of such fees was approximately $339,414. The

17

---



suspended
fees were paid in full by the Trust in January 2014 and are included within general and administrative expenses for the nine months ended September 30, 2014.

On
October 31, 2013, the Trust issued a press release announcing that the Partnership had consummated the sale (the "2013 Royalty Sale" and, together with the 2011 Royalty Sale,
the "Royalty Sales") of 25% of its remaining interest in the Original Royalty (or 5% of 8/8ths), which generated $1,200,000 in gross proceeds and occurred as part of a formal auction process for the
Partnership's remaining overriding royalty interest in the Royalty Properties. The Trust received from the Partnership a distribution of approximately $1,151,885, representing 99.99% of the net
proceeds from the sale of $1,152,000. The 2013 Royalty Sale was made to RNR Production on October 31, 2013, though the assignment was effective as of August 1, 2013. The Trust used
approximately $300,000 of the net proceeds received in October 2013 to repay the Trust's indebtedness under a previous note payable to BONYM and used the remaining net proceeds solely for the payment
of expenses of the Trust. Following the 2013 Royalty Sale, the Partnership has retained a 60% interest in the Original Royalty, and thus the Partnership will receive in the future only 15% of the Net
Proceeds when there are sufficient Net Proceeds for distribution on the Partnership's Royalty.

In
March 2014, the Trustees again unanimously determined to suspend future payments of fees to the Trustees effective as of January 1, 2014, until a date to be determined in the
future by the Trustees. As of September 30, 2015, the accumulated amount of such suspended fees was approximately $414,918 in the aggregate. The cumulative suspended fees will be recorded as an
expense of the Trust when invoiced by the Trustees and paid.

On
October 1, 2014, BONYM made a loan to the Trust in the amount of $363,000, and the Corporate Trustee, as the borrower, entered into a Demand Promissory Note (the "2014 Note")
with BONYM, as lender, relating to the unsecured $363,000 advance, which evidenced an extension of credit for borrowed money authorized under Section 6.08 of the Trust Agreement. On
September 25, 2015, BONYM made an additional advance to the Trust in the amount of $484,000 and the Corporate Trustee, as the borrower, entered into a Renewal Demand Promissory Note (the "2015
Note") with BONYM, as lender, relating to (i) the unsecured $484,000 advance, (ii) the renewal and extension of the 2014 Note, and (iii) previous advances in the amount of
$209,885 made by BONYM on behalf of the Trust. The 2015 Note bears interest at the rate of one-half percent (0.5%) per annum. Pursuant to the terms of the 2015 Note, all amounts outstanding under the
2015 Note including accrued and unpaid interest will be due and payable in cash on the earliest to occur of (i) the date written demand for payment is made by BONYM or
(ii) December 31, 2016. The Trust may prepay any outstanding principal and accrued and unpaid interest under the 2015 Note, in whole or in part, at any time without penalty. In addition,
the accrued and unpaid interest remaining due from the 2014 Note in the amount of $1,790 is due and payable concurrently with the payment of the 2015 Note. During the three and nine months ended
September 30, 2015, a portion of the proceeds from the 2014 Note, as renewed and extended by the 2015 Note, were used to pay Trust expenses.

As
indicated above, the Trustees have previously authorized the Trust to borrow funds and the Partnership to sell portions of the Original Royalty in an effort to pay the ongoing costs
and expenses incurred by the Trust in fulfilling its obligations under the Trust Agreement. As a result of the ongoing costs and expenses of the Trust and the lack of any distributions or assurances
of future distributions, on July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate Court of Travis County, Texas (the
"Court"). The Petition requests the Court to modify the Trust Agreement to (1) allow for the termination of the Trust by a court order,

18

---



and
(2) allow the Trustees, as necessary to fulfill the purposes of the Trust and without Unit holder approval to (a) sell all or any portion of the Trust's interests in the Partnership
or any other assets of the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding
(the "Probate Proceeding") are to permit the Trustees to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities,
to the Unit holders; and, to, thereafter terminate the Partnership and the Trust. It is anticipated that the Trust will fund the costs and expenses of the Probate Proceeding with loans from BONYM.
However, BONYM will continue to evaluate the Probate Proceeding and the costs and expenses. The Trust has completed the process serving the Petition on the Trust's Unit holders. The Court appointed an
attorney ad litem to represent any Unit holders that were not personally served. The Court appointed attorney ad litem filed a Counterclaim against the Trust on
November 16, 2015 requesting (1) an order to sell all of the Royalty Interests, and (2) an accounting of the general and administrative expenses of the Trust from 2008 through the
present. The trial is currently set for January 15, 2016; however, it is possible that the Counterclaim filed by the attorney ad litem could result in a delay. There can be no assurances
whether the Court will grant the requested relief and, if such relief is granted, when such actions will be completed. It is anticipated that any loans obtained by the Trust to pay the costs and
expenses of the Probate Proceeding will be repaid from any proceeds received by the Trust, including any proceeds received upon any sale of the remaining Royalty and, as a result, there can be no
assurances as to amount of net proceeds resulting from any such sale of the Royalty that may be available for distribution to the Unit holders.

On
October 7, 2008, the Trust announced that production from the two most significant oil and gas properties associated with the Trust had ceased following damage inflicted by
Hurricane Ike in September 2008. On December 19, 2008, the Trust announced its fourth quarter distribution of approximately $0.7 million, which was paid on January 9, 2009. Based
on lower production as a result of shutdowns and damages to producing assets because of Hurricane Ike, the Trust's scheduled distribution for the fourth quarter of 2008 was severely negatively
impacted and no distributions have been made to Unit holders since January 9, 2009. In the fourth quarter of 2010, Chevron withdrew $4,304,894 from the Special Cost Escrow account of the
Working Interest Owners (a reserve fund for certain costs) to cover expenses incurred in connection with the plugging and abandonment of Eugene Island 339, which served to reduce the amount by which
production costs exceeded the proceeds from production; however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the terms of the
Conveyance if, and when, Net Proceeds would otherwise be payable on the Partnership's interest in the Royalty. As a result of the damage inflicted by Hurricane Ike, Net Proceeds will continue to be
severely impacted by reduced production, from historical levels, and the amount of expenditures incurred that are associated with such damages, including any remaining expenditures required to plug
and abandon the wells on Eugene Island 339.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the
Trust that the aggregate cost to the Original Royalty to plug and abandon the wells, remove and abandon platforms and infrastructure and remediate the surface subject to the overriding royalty
interest on Eugene Island 339 was approximately $19.8 million and that no further expenses of this nature relating to prior hurricane damage are expected to be incurred. In December 2009,
Chevron and Arena Offshore, LP ("Arena") entered into a participation agreement to assist in the redevelopment as a farmout of portions of Eugene Island 338 and 339 (the participation
agreement, as amended, the "Arena Agreement"). Pursuant to the terms of the Arena Agreement, Arena had the right to earn an

19

---



assignment
of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339 following completion of certain drilling and development operations. Following completion of the first well
on Eugene Island 339 by Arena and other drilling and development operations in the fourth quarter of 2012, Chevron assigned 65% of Chevron's working interests in Eugene Island 338 and Eugene Island
339 to Arena, effective as of December 15, 2009, the effective date of the Arena Agreement. In accordance with the Arena Agreement, the working interest assigned to Arena is not burdened by the
Royalty, and the Royalty held by the Partnership with respect to such properties has been reduced proportionately. As a result of such assignment, the Royalty held by the Partnership on Eugene Island
339 has been reduced by 65%. See "Operations" for a more detailed discussion of Eugene Island 339.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline. Production has since been restored at Ship Shoal
182/183. See "Operations" for a more detailed discussion of Ship Shoal 182/183.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The lease
for West Cameron 643 expired on May 31, 2010 and the lease for East Cameron 371 expired on March 31, 2010. Plugging and abandoning of the wells at West Cameron 643 was completed
in October 2012. The abandonment work for East Cameron 371 has been completed.

Chevron
reached settlements that provided Chevron with insurance proceeds associated with damages that Chevron's assets sustained from Hurricane Ike. The allocated portion thereof with
respect to the Partnership's interest in Eugene Island 339, as a Royalty Property, was approximately $781,000. Chevron applied $400,000 thereof in the first quarter of 2011 and applied the remaining
amount of approximately $381,000 in the fourth quarter of 2012. All such allocated insurance proceeds were applied to the Partnership's portion of the aggregate cost to plug and abandon the wells
subject to the Royalty on Eugene Island 339. Chevron has completed the work associated with the wells on Eugene Island 339 and informed the Trust that the aggregate cost to the Original Royalty to
plug and abandon the wells, remove and abandon platforms and infrastructure and remediate the surface subject to the overriding royalty interest on Eugene Island 339 was approximately
$19.8 million and that no further expenses of this nature relating to prior hurricane damage are expected to be incurred. If Production Costs of the Royalty Properties owned by a Working
Interest Owner exceed the Gross Proceeds from the Royalty Properties, owned by such Working Interest Owner, the Trust will not receive Net Proceeds from such Working Interest Owner until future
proceeds from production from the Royalty Properties owned by such Working Interest Owner exceed the total of the excess costs plus accrued interest at a
rate equal to one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the
prime interest rate at the end of the preceding quarterly period, during the deficit period. As a result of the damage inflicted by Hurricane Ike, the Trust has not received Net Proceeds from Chevron,
as the Working Interest Owner, since December 2008. As of July 31, 2015, aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related
proceeds of production from the Royalty Properties by approximately $1.7 million, net to the entire Original Royalty (or $1.0 million applicable to the Trust). The excess development and
production costs have decreased from $2.8 million, as of October 31, 2014 to $1.7 million, net to the entire Original Royalty, as of July 31, 2015, reflecting

20

---



increased
production from the Royalty Properties. While Chevron has not withdrawn any funds from the Special Cost Escrow Account since the fourth quarter of 2010, additional deposits to the Special
Cost Escrow account would be required in future periods in accordance with the terms of the Conveyance if, and when, Net Proceeds from Chevron, as the Working Interest Owner, would otherwise be
payable on the Royalty.

Although
the Trust has recently received nominal distributions from Fieldwood Energy Offshore LLC, as the Working Interest Owner of Eugene Island 342, it is anticipated that any such
future distributions will continue to be nominal in amount and the Trust will not make any distributions to its Unit holders until the Trust's indebtedness is paid in full. Accordingly, it is expected
that there will not be sufficient Net Proceeds from the Royalty Properties to make distributions for some period of time in the future. At this time, the ultimate outcome of these various matters
cannot be determined. See "Operations"

Substantial
uncertainties exist with regard to future oil and gas prices, which are subject to material fluctuations due to changes in production levels and pricing and other actions
taken by major petroleum producing nations, as well as the regional supply and demand for oil and gas, worldwide political conditions, weather, industrial growth, conservation measures, competition,
economic conditions generally and other variables.

In
accordance with the provisions of the Trust Agreement, generally all Net Proceeds received by the Trust, net of Trust general and administrative expenses and any cash reserves
established for the payment of contingent or future obligations of the Trust, are distributed currently to the Unit holders. Historically the Trust generally maintained a cash reserve, equal to
approximately three times the average annual expenses of the Trust during each of the then past three years, to provide for future
administrative expenses in connection with the winding up of the Trust. However, as a result of the damage inflicted upon certain of the Royalty Properties by Hurricane Ike in September 2008, the
Trust has not received sufficient Net Proceeds to maintain the reserve at such level. During the three and nine months ended September 30, 2015, the Trust utilized $96,765 and $334,255,
respectively, of the proceeds from the 2015 Note, 2014 Note and cash advances from BONYM to pay for Trust expenses. As of September 30, 2015, the reserve balance was $0. Including the proceeds
from the 2015 Note, and previous cash advances from BONYM included in the principal amount of the 2015 Note, the Trust's available cash was approximately $487,276 at September 30, 2015.

The
accompanying condensed financial statements have been prepared assuming that the Trust will continue as a going concern. Financial statements prepared on the going concern basis
assume the realization of assets and the settlement of liabilities in the normal course of business. The lack of Net Proceeds and the inability to maintain adequate cash reserves raise substantial
doubt about the Trust's ability to continue as a going concern. Certain potential alternatives available to the Trustees are described in Note 6 to the condensed financial statements. The
condensed financial statements do not include any adjustments that might result from the outcome of this uncertainty. See Notes 2 and 6 to the condensed financial statements.

Future Net Revenues and Termination of the Trust

Based on a reserve study provided to Chevron, as the Managing General Partner of the Partnership, by DeGolyer and MacNaughton,
independent petroleum engineers, as of October 31, 2014 future net revenues attributable to the Trust's royalty interests were estimated at $7.3 million. Estimates

21

---



of
proved oil and gas reserves attributable to the Partnership's royalty interest are based on existing economic and operating conditions in effect at October 31, 2014 in order to correspond
with distributions to the Trust. Such reserve study also indicates that approximately 69% of the future net revenues from the Royalty Properties are expected to be received by the Trust by
October 31, 2017. The reserve study does include projected reserves attributable to the four wells drilled by Arena on Eugene Island 339 but does not include any capital expenditures for any
redevelopment of Eugene Island 339. As indicated above, the revenue values in the reserve report were estimated using the initial costs
provided by Chevron and the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period ended October 31, 2014. The prices of oil and natural gas
have declined significantly since October 31, 2014 and it is anticipated that the lower oil and natural gas prices over the 12-month period ended October 31, 2015 will result in a
reduction in the total future net revenues attributable to the Partnership's interest in the Royalty as of October 31, 2015. Because the Trust will terminate in the event estimated future net
revenues attributable to the Partnership's interest in the Royalty fall below $1.2 million (assuming no further sales of any interests in the Royalty), it would be possible for the Trust to
terminate even though some or all of the Royalty Properties continued to have remaining productive lives. Upon termination of the Trust, the Trustees will sell for cash all of the assets held in the
Trust estate and make a final distribution to Unit holders of any funds remaining after all Trust liabilities have been satisfied. The estimates of future net revenues discussed above are subject to
large variances from year to year and should not be construed as exact. There are numerous uncertainties present in estimating future net revenues for the Royalty Properties. The estimate may vary
depending on changes in market prices for crude oil and natural gas, the recoverable reserves, annual production and costs assumed by DeGolyer and MacNaughton. In addition, future economic and
operating conditions as well as results of future drilling plans may cause significant changes in such estimate. The discussion set forth above is qualified in its entirety by reference to the 2014
10-K. The 2014 10-K is available at the website of the Securities and Exchange Commission ("SEC") atwww.sec.govor upon request from the Corporate
Trustee.

Special Cost Escrow Account

The Conveyance provides for reserving funds for estimated future "Special Costs" of plugging and abandoning wells, dismantling
platforms and other costs of abandoning the Royalty Properties, as well as for the estimated amount of future drilling projects and other capital expenditures on the Royalty Properties. As provided in
the Conveyance, the amount of funds to be reserved is determined based on factors including estimates of aggregate future production costs, aggregate future Special Costs, aggregate future net
revenues and actual current net proceeds. Deposits into this account reduce current distributions and are placed in an escrow account and invested in short-term certificates of deposit. Such account
is herein referred to as the "Special Cost Escrow" account. The Trust's share of interest generated from the Special Cost Escrow account serves to reduce the Trust's share of allocated production
costs. Special Cost Escrow funds will generally be utilized to pay Special Costs to the extent there are not adequate current net proceeds to pay such costs. Special Costs that have been paid are no
longer included in the Special Cost Escrow calculation. Deposits to the Special Cost Escrow account will generally be made when the balance in the Special Cost Escrow account is less than 125% of
estimated future Special Costs and there is a Net Revenues Shortfall (a calculation of the excess of estimated future costs over estimated future net revenues pursuant to a formula contained in the
Conveyance). When there is not a Net Revenues Shortfall, amounts in the Special Cost Escrow account will generally be released, to the extent that Special Costs have been incurred. Amounts in the
Special

22

---



Cost
Escrow account will also be released when the balance in such account exceeds 125% of estimated future Special Costs. In the first nine months of 2015, there were no funds released or escrowed
from the Special Cost Escrow account. As of September 30, 2015, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the
condensed financial statements of the Trust. The discussion of the terms of the Conveyance and Special Cost Escrow account contained herein is qualified in its entirety by reference to the Conveyance
itself, which is an exhibit to this Form 10-Q and is available upon request from the Corporate Trustee.

Aggregate
development and production costs in excess of the related proceeds for the royalty properties, as of July 31, 2015, were approximately $1.7 million, net to the
entire Royalty ($1.0 million applicable to the Trust); however, additional deposits to the Special Cost Escrow account would be required in future periods in accordance with the Conveyance if,
and when, Net Proceeds from Chevron, as the Working Interest Owner, would otherwise be payable on the Royalty. During the first nine months of 2015 and 2014, respectively, there were no funds released
from or escrowed into the Special Cost Escrow account. As of September 30, 2015, $1,000 remained in the Special Cost Escrow account.

In
connection with the Royalty Sales, the Partnership has assigned an aggregate 40% of its rights and obligations with respect to the Special Cost Escrow account.

Chevron,
in its capacity as Managing General Partner of the Partnership, has advised the Trust that additional deposits to the Special Cost Escrow account will be required in future
periods in connection with other production costs, other abandonment costs, other capital expenditures and changes in the estimates and factors described above. Such deposits could result in a
significant reduction in Royalty income in the periods in which such deposits are made.

Three Months Ended September 30, 2015 and 2014



Royalty income was $0 for each of the three months ended September 30, 2015 and 2014. Gross proceeds for the underlying Royalty
Properties exceeded development and production costs by $326,576, or $195,946 attributable to the Trust, for the production period of May, June and July 2015 attributable to the three months ended
September 30, 2015 and by $2,733,945, or $683,486 attributable to the Trust for the production period of May, June and July 2014 attributable to the three months ended September 30,
2014. The Net Proceeds were applied to reduce the accumulated excess cost carry forward, which represents the amount by which the aggregate development and production costs for the Royalty Properties
since November 2008 have exceeded the related proceeds of the protection, and as a result there was no royalty income for the quarters ended September 30, 2015 and 2014.

General
and administrative expenses for the Trust were $96,765 for the three months ended September 30, 2015 compared to $187,957 for the three months ended September 30,
2014. The decrease is due, in part, to the timing of the recording of expenses.

The
reserve for future Trust expenses did not change from June 30, 2015 to September 30, 2015 and remained at $0.

There
was no distributable income for each of the three months ended September 30, 2015 and September 30, 2014 and therefore no distributions to Unit holders.

23

---



For
the three months ended September 30, 2015 and September 30, 2014, the Trust had undistributed net income of $195,946 and $410,092, respectively, representing the
Trust's portion of the undistributed net income of $1,306,304 and $2,733,945 associated with the Royalty Properties for the three months ended September 30, 2015 and 2014. As of July 31,
2015, the cumulative undistributed net loss was $1.7 million, net to the entire Original Royalty ($1.0 million net to the Trust). Undistributed net loss
represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is
carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production
exceed the total of the excess costs plus applicable accrued interest.



The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing
General Partner. The Trustees have no control over these operations or internal controls relating to this information.

Volumes
and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Natural Gas and Gas Products

Gas revenues decreased $236,000, or 67%, to $115,077 in the third quarter of 2015 from $351,077 in the third quarter of 2014. Gas
volumes during the third quarter of 2015 decreased 44% to 41,263 Mcf from 73,562 Mcf in the third quarter of 2014. The average price received for natural gas decreased approximately 42%
from an average price of $4.82 per Mcf in the third quarter of 2014 to $2.79 per Mcf in the third quarter of 2015, excluding the impact of the adjustments for Eugene Island 339 and Eugene
Island 342. Gas products revenue decreased $24,087, or 57%, to $17,858 in the third quarter of 2015 from $41,945 in the third quarter of 2014. Gas products volumes during the third quarter of
2015 decreased 29% to 47,820 gallons, compared to 67,075 gallons in the third quarter of 2014.

Crude Oil and Condensate

Crude oil and condensate revenues decreased $1,579,485, or 43%, to $2,109,957 in the third quarter of 2015 from $3,689,442 in the third
quarter of 2014. The decrease in revenues is the result of a decrease in the average price received for crude oil and condensate for the third quarter of 2015. The average price received for crude oil
and condensate production decreased approximately 41%, or $42.41, to $60.72 per barrel in the third quarter of 2015 from $103.13 per barrel in the third quarter of 2014, excluding the impact of the
adjustments for Eugene Island 339 and Eugene Island 342. Oil volumes decreased 3% from 35,777 barrels in the third quarter of 2014 to 34,749 barrels in the third quarter of 2015. The
decrease was primarily due to a temporary shut in at Eugene Island 339 during the third quarter of 2015, thus decreasing crude oil production during 2015 when compared to 2014.

Capital Expenditures

Capital expenditures decreased by $17,802, or 99%, from $18,031 in the third quarter of 2014 to $229 in the third quarter of 2015. The
higher amount of capital expenditures during the third quarter of 2014 relates primarily to facility improvement projects and drilling and completion costs associated with a well at Ship Shoal
182/183.

24

---





Production Expenses

Production expenses decreased by $394,131, or 30%, from $1,330,489 in the third quarter of 2014 to $936,358 in the third quarter of
2015. The decrease in operating expenses is due to the decrease of maintenance projects at Ship Shoal 169 in the third quarter of 2015 as compared to the third quarter of 2014.

Special Cost Escrow Account

In the third quarter of 2015, there were no funds released from or escrowed into the Special Cost Escrow account. As of
September 30, 2015, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust.
The Special Cost Escrow account is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost
Escrow account, see "Special Cost Escrow Account" above.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the third quarter of 2015 as compared to operations for
the third quarter of 2014 based on gross revenues generated during these periods combined.

Eugene Island 339

Net crude oil revenues decreased from $546,816 in the third quarter of 2014 to $501,115 in the third quarter of 2015, due to a decrease
in the average crude oil price received from $103.03 per barrel in the third quarter of 2014 to $58.83 per barrel in the third quarter of 2015. This decrease was partially offset by an increase in net
crude oil production from 5,308 barrels in the third quarter of 2014 to 8,518 barrels in the third quarter of 2015. Crude oil production increased due to wells, which were shut-in for
part of the prior year quarter for equipment repairs, coming back online for the current year quarter. Gas revenues decreased from $29,659, in the third quarter of 2014 to $18,399 in the third quarter
of 2015, due primarily to a decrease in the average natural gas price received from $5.00 per Mcf in the third quarter of 2014 to $3.11 per Mcf in the third quarter of 2015. Capital expenditures were
$0 in the third quarter of 2014 and the third quarter of 2015. Operating expenses increased from $12,353 in the third quarter of 2014 to $44,781 in the third quarter of 2015 due to increased
maintenance costs during the third quarter of 2015 compared to the third quarter of 2014.

Ship Shoal 182/183

Net crude oil revenues decreased from $3,043,860 in the third quarter of 2014 to $1,562,975 in the third quarter of 2015, due to a
decrease in the average crude oil price received from $103.17 per barrel in the third quarter of 2014 to $61.44 per barrel for the same period in 2015. Net crude oil production slightly decreased as a
result of normal operating fluctuations from 29,505 barrels in the third quarter of 2014 to 25,440 barrels in the third quarter of 2015. Gas revenues decreased from $314,024 in the third
quarter of 2014 to $93,909 in the third quarter of 2015, due to a
decrease in gas production from 65,313 Mcf in the third quarter of 2014 to 34,233 Mcf in the third quarter of 2015 as a result of the pipeline being temporarily shut in during the third
quarter of 2015. The average gas revenue price received also decreased from $4.81 per Mcf in the third quarter of 2014 to $2.74 per Mcf for the same

25

---



period
in 2015. Capital expenditures decreased from $18,010 in the third quarter of 2014 to $231 in the third quarter of 2015. Operating expenses decreased from $1,147,246 in the third quarter of 2014
to $787,045 for the same period in 2015 due to several maintenance projects during the third quarter of 2014 and decreased production during the third quarter of 2015.

South Timbalier 36/37

Net crude oil revenues decreased from $98,766 in the third quarter of 2014 to $40,391 for the same period in 2015 due to a decrease in
oil production volumes from 965 barrels in the third quarter of 2014 to 685 barrels in the third quarter of 2015 due to a well being temporarily shut in during the third quarter 2015.
There was also a decrease in the average crude oil price received from $102.40 per barrel in the third quarter of 2014 to $58.99 per barrel in the third quarter of 2015. Gas revenues decreased from
$7,326 in the third quarter of 2014 to $2,727 in the third quarter of 2015 due to a decrease in the average natural gas price received from $3.18 per Mcf in the third quarter of 2014 to $2.49 per Mcf
in the third quarter of 2015. Gas production also decreased from 2,305 Mcf in the third quarter of 2014 to 1,095 Mcf in the third quarter of 2015 due to shut ins for maintenance work
during the third quarter 2015. Capital expenditures decreased from $21 in the third quarter of 2014 to $0 in the third quarter of 2015. Operating expenses decreased from $12,706 in the third quarter
of 2014 to $11,926 in the third quarter of 2015 due to higher maintenance repairs conducted during the third quarter of 2014 and lower production during the third quarter 2015.

Eugene Island 342

Net crude oil revenues increased from $0 in the third quarter of 2014 to $5,476 in the third quarter of 2015. This increase is
primarily due to a prior period adjustment in net crude oil production from 0 barrels in the third quarter of 2014 to 107 barrels in the third quarter of 2015. Gas revenues were $68 and
gas production was 15 Mcf in the third quarter of 2014, compared to gas revenues of $41 and gas production of 15 Mcf in the third quarter of 2015. As the underlying interest in Eugene
Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the third quarter of 2015 and 2014.

Nine Months Ended September 30, 2015 and 2014



Royalty income was $0 for the nine months ended September 30, 2015 and 2014. Gross proceeds for the underlying Royalty
Properties exceeded development and production costs by $4,261,214, or $639,183 attributable to the Trust, for the production period of November and December 2014 and January, February, March, April,
May, June and July 2015 attributable to the nine months ended September 30, 2015 and by $5,438,877, or $815,831 attributable to the Trust for the production period of November and December 2013
and January, February, March, April, May, June and July 2014 attributable to the nine months ended September 30, 2014. The Net Proceeds were applied to reduce the accumulated excess cost carry
forward, which represents the amount by which the aggregate development and production costs for the Royalty Properties since November 2008 have exceeded the related proceeds of the protection, and as
a result there was no royalty income for the nine months ended September 30, 2015 and 2014.

26

---



General
and administrative expenses for the Trust were $334,255 for the nine months ended September 30, 2015 compared to $853,918 for the nine months ended September 30,
2014. The decrease is due to the timing of the recording of expenses, of which $339,414 related to payment of the suspended Trustee fees that was paid in January 2014.

The
reserve for future Trust expenses did not change from December 31, 2014 to September 30, 2015 and remained at $0.

There
was no distributable income for each of the nine months ended September 30, 2015 and September 30, 2014 and therefore no distributions to unit holders.

For
the nine months ended September 30, 2015 and September 30, 2014, the Trust had undistributed net income of $639,183 and $815,831, respectively, representing the Trust's
portion of the undistributed net income of $4,261,214 and $5,438,877 associated with the Royalty Properties for the nine months ended September 30, 2015 and 2014. For the nine months ended
September 30, 2014, net income for the Royalty Properties included additional proceeds of $72,443, net to the Trust, as a result of an audit adjustment for the Royalty Properties. The
cumulative undistributed net loss for the Trust was $1.7 million as of July 31, 2015. Undistributed net loss represents the amount of development and production costs associated with the
Royalty that exceed the proceeds of production from the Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by
the related Working Interest Owner(s). The Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest.



The following financial and operational information has been based on information provided to the Corporate Trustee by the Managing
General Partner. The Trustees have no control over these operations or internal controls relating to this information.

Volumes
and dollar amounts discussed below represent amounts recorded by the Working Interest Owners unless otherwise specified.

Natural Gas and Gas Products

Gas revenues decreased $196,399, or 27%, to $539,510 in the first nine months of 2015 from $735,909 in the first nine months of 2014.
Gas volumes during the first nine months of 2015 increased 5% to 158,499 Mcf from 151,382 Mcf in the first nine months of 2014. Excluding the impact of prior period adjustments, the
average price received for natural gas decreased approximately 31% from an average price, excluding adjustments, of $4.90 per Mcf in the first nine months of 2014 to $3.40 per Mcf in the first
nine months of 2015. Also as a result of the adjustments, gas products volumes during the first nine months of 2015 decreased 17% to 155,775 gallons, compared to 186,967 gallons in the
first nine months of 2014.

Crude Oil and Condensate

Crude oil and condensate revenues decreased $2,905,487, or 31%, to $6,502,663 in the first nine months of 2015 from $9,408,150 in the
first nine months of 2014. Excluding the impact of prior period adjustments, the average price received for crude oil and condensate production decreased 39%, or

27

---



$39.85,
to $62.02 per barrel in the first nine months of 2015 from $101.87 per barrel in the first nine months of 2014. Oil volumes increased 14% from 92,202 barrels in the first nine months of
2014 to 104,851 barrels in the first nine months of 2015. The increase in volumes is primarily due to wells coming back online after multiple shut ins for facility improvement projects during
the first nine months of 2014 at Ship Shoal 182/183. In addition, the increase in volumes is due to increased production in the first nine months of 2015 at Eugene Island 339 due to the completion of
the K-11 well on Eugene Island 339 which came online in the fourth quarter of 2014.

Capital Expenditures

Capital expenditures decreased by $174,675, or 99%, from $175,608 in the first nine months of 2014 to $933 in the first nine months of
2015. The higher amount of capital expenditures during the first nine months of 2014 relate primarily to facility improvement projects and drilling and completion costs associated with a well at Ship
Shoal 182/183. There were no significant facility improvement projects or drilling and completion costs for Ship Shoal 182/183 or any other of the properties during the first nine months of 2015.

Production Expenses

Production expenses decreased by $1,827,258, or 39%, from $4,668,967 in the first nine months of 2014 to $2,841,709 in the first nine
months of 2015. The decrease in operating expenses is due to a decrease in maintenance projects at Ship Shoal 169 in the first nine months of 2015 as compared to the first nine months of 2014.

Special Cost Escrow Account

In the first nine months of 2015, there were no funds released from or escrowed into the Special Cost Escrow account. As of
September 30, 2015, $1,000 remained in the Special Cost Escrow account. The funds held in the Special Cost Escrow account are not reflected in the condensed financial statements of the Trust.
The Special Cost Escrow account is set aside for estimated abandonment costs and future capital expenditures, as provided for in the Conveyance. For additional information relating to the Special Cost
Escrow account, see "Special Cost Escrow Account" below.

Summary By Property

Listed below is a summary of operations of the principal Royalty Properties for the first nine months of 2015 as compared to operations
for the first nine months of 2014 based on gross revenues generated during these periods combined.

Eugene Island 339

Eugene Island 339 net crude oil revenues decreased from $1,942,299 in the first nine months of 2014 to $1,722,499 in the first nine
months of 2015, due to a decrease in the average crude oil price received from $101.26 per barrel in the first nine months of 2014 to $62.01 per barrel in the first nine months of 2015. This decrease
was partially offset by an increase in net crude oil production from 19,181 barrels in the first nine months of 2014 to 27,778 barrels in the first nine months of 2015. Gas revenues
decreased from $129,309 in the first nine months of 2014 to $63,853 in the first nine months of 2015, due primarily to a decrease in gas production from 26,904 Mcf in the first nine months of
2014

28

---



to
17,471 Mcf in the first nine months of 2015. Capital expenditures were $0 the first nine months of 2015 and 2014, respectively. Operating expenses increased from $68,760 in the first nine
months of 2014 to $103,567 in the first nine months of 2015 due primarily to increased maintenance costs in the first nine months of 2015 as compared to the first nine months of 2014.

Ship Shoal 182/183

Ship Shoal 182/183 net crude oil revenues decreased from $7,052,957 in the first nine months of 2014 to $4,901,958 in the first nine
months of 2015, due to a decrease in the average crude oil price received from $102.31 per barrel in the first nine months of 2014 to $63.62 per barrel for the same period in 2015. This decrease was
partially offset by an increase in net crude oil production from 68,935 barrels in the first nine months of 2014 to 77,053 barrels in the first nine months of 2015. The increase in
volumes was primarily due to multiple shut ins for facility improvement projects during the first nine months of 2014. Gas revenues decreased from $571,375 in the first nine months of 2014 to $438,666
in the first nine months of 2015, due to a decrease in in the average gas revenue price received from $4.96 per Mcf in the first nine months of 2014 to $3.31 per Mcf for the same period in 2015. This
decrease was partially offset by an increase in gas production from 115,127 Mcf in the first nine months of 2014 to 132,502 Mcf in the first nine months of 2015 as a result of the shut
ins during the first nine months of 2014. Capital expenditures decreased from $171,767 in the first nine months of 2014 to $1,091 in the first nine months of 2015. Operating expenses decreased from
$4,103,803 in the first nine months of 2014 to $2,407,955 for the same period in 2015 due to several maintenance projects winding down during the first nine months of 2014.

South Timbalier 36/37

South Timbalier 36/37 crude oil revenues decreased from $282,864 in the first nine months of 2014 to $179,409 for the same period in
2015 due primarily to a decrease in the average crude oil price received from $100.81 per barrel in the first nine months of 2014 to $65.14 per barrel in the first nine months of 2015. Oil production
volumes also decreased from 2,806 barrels in the first nine months of 2014 to 2,754 barrels in the first nine months of 2015. Gas revenues decreased from
$25,465 in the first nine months of 2014 to $9,802 in the first nine months of 2015 due to a decrease in the average natural gas price received from $3.70 per Mcf in the first nine months of 2014 to
$3.11 per Mcf in the first nine months of 2015. Gas production also decreased from 6,891 Mcf in the first nine months of 2014 to 3,152 Mcf in the first nine months of 2015. Capital
expenditures decreased from an expense of $3,841 in the first nine months of 2014 to a benefit of $157 in the first nine months of 2015 primarily due to the sale of some materials at South Timbalier
36/37. The costs in the first nine months of 2014 were primarily associated with facility improvements. Operating expenses decreased from $55,782 in the first nine months of 2014 to $40,482 in the
first nine months of 2015 due to higher maintenance repairs conducted during the first nine months of 2014.

Eugene Island 342

Net crude oil revenues decreased from $130,031 in the first nine months of 2014 to negative $301,203 in the first nine months of 2015.
This decrease is primarily due to a prior period adjustment in net crude oil production from 1,282 barrels in the first nine months of 2014 to negative 2,733 barrels in the first nine
months of 2015. Gas revenues were $27,188 and gas production was 5,373 Mcf in the first nine months of 2015, compared to gas revenues of $9,760 and gas production of 2,460 Mcf in the

29

---



first
nine months of 2014. As the underlying interest in Eugene Island 342 is an overriding royalty interest, there were no capital or operating expenses recorded in the first nine months of 2015 and
2014.

Operations

The following operational information has been based on information provided to the Corporate Trustee by Chevron as the Managing
General Partner of the Partnership. The Trustees have no control over these operations or internal controls relating to this information.

The
platforms and wells on Eugene Island 339 were completely destroyed by Hurricane Ike in September 2008. Chevron has completed the work associated with the wells on Eugene Island 339
and informed the Trust that the aggregate cost to the Original Royalty to plug and abandon the wells, remove and abandon platforms and infrastructure and remediate the surface subject to the
overriding royalty interest on Eugene Island 339 was approximately $19.8 million and that no further expenses of this nature relating to prior hurricane damage are expected to be incurred.

Generally,
if production ceases from an outer continental shelf lease, like that for Eugene Island 339, production must be restored or drilling operations must commence within
180 days of the cessation of production (which was in early March 2009 with respect to Eugene Island 339 given the cessation of production in September 2008 resulting from Hurricane Ike), or
the lease will be terminated. Alternatively, an operator of a lease may request a Suspension of Production (each, an "SOP"), that, if approved by the regional supervisor of the Bureau of Ocean Energy
Management allows additional time to restore production in the event of certain circumstances, such as hurricanes and other events beyond the control of the operator. Although Chevron successfully
obtained a series of SOPs and, with the participation of Arena, obtained additional SOPs resulting in the restoration of limited production at Eugene Island 339, other Working Interest Owners have
been unable to timely restore production or obtain an SOP and as a result, many of the leases covering the Royalty Properties have been terminated or expired thereby reducing the proceeds payable to
the Trust.

On
December 15, 2009, Chevron entered into the Arena Agreement with Arena to assist in the redevelopment as a farmout of portions of Eugene Island 338 and 339. Pursuant to the
terms of the Arena Agreement, Arena could earn an assignment of 65% of Chevron's working interests in Eugene Island 338 and Eugene Island 339. Chevron holds a 50% interest in Eugene Island 339, which
interest is included in the 5500' and the 4500' sand units; 42.05% of all production from the 5500' sand unit is allocated to Eugene Island 339 and 38.50% of the gas production and 24.44% of the oil
production from the 4500' sand unit is allocated to Eugene Island 339. Pursuant to the terms of the Conveyance, Chevron may enter into a farmout agreement whereby Chevron assigns any portion of its
interest in the Royalty Properties free and clear of the Original Royalty, and the Original Royalty will be reduced in the same proportion as that in which the Royalty Property is reduced. Under the
terms of the Conveyance, a "farmout agreement" is defined as an agreement with a third party requiring or permitting the performance of drilling or development operations on a Royalty Property, and
for which all or substantially all of the consideration is the transfer of an interest in a Royalty Property. On August 4, 2012, Arena completed installation of the remaining topside decks of
the structure and on August 16, 2012, Arena commenced mobilization of the H&P 100 platform rig components. On September 28, 2012, Arena spud the OCS-G 2318 Well No. K002
and production from this well was realized in the fourth quarter of 2012. Pursuant to the terms of the Arena Agreement, following completion of the well and the other drilling and development
operations, Chevron assigned 65% of

30

---



Chevron's
working interests in Eugene Island 338 and Eugene Island 339 to Arena, effective as of December 15, 2009, the effective date of the Arena Agreement. In accordance with the Arena
Agreement, the working interest assigned to Arena is not burdened by the Original Royalty, and the Royalty held by the Partnership with respect to such properties has been reduced proportionately. As
a result of such assignment, the Royalty held by the Partnership on Eugene Island 339 has been reduced by 65%.

Production
at Ship Shoal 182/183 ceased following damage inflicted by Hurricane Ike in September 2008. While the hurricane caused limited surface damage to the facilities at Ship Shoal
182/183, all of the wells at Ship Shoal 182/183 were shut-in following hurricane-related damage to a third-party transporter's natural gas pipeline and production has since been restored.

In
addition, production from West Cameron 643 and East Cameron 371 ceased following damage inflicted by Hurricane Ike in September 2008 to third-party transporters' pipelines. The lease
for West Cameron 643 expired on May 31, 2010 and the lease for East Cameron 371 expired on March 31, 2010. Plugging and abandoning of the wells at West Cameron 643 was completed in
October 2012. Field abandonment work for East Cameron 371, including the related wells, equipment platforms and any field infrastructure, remains to be completed.

Overview of Production, Prices and Royalty Income

The following schedule provides a summary of the volumes and weighted average prices for crude oil and condensate and natural gas
recorded by the Working Interest Owners for the Royalty Properties, as well as the Working Interest Owners' calculations of the Net Proceeds and Royalties paid to the Trust during the periods
indicated.

Royalty Properties Three
Months Ended
September 30,(1)

Royalty Properties Nine
Months Ended
September 30,(1)2015

2014

2015

2014Crude oil and condensate (bbls)


34,749


35,777


104,851


92,202Natural gas and gas products (Mcfe)


49,233


84,741


184,461


182,543Crude oil and condensate average price, per bbl(2)

$
60.72

$
103.12

$
62.02

$
102.04Natural gas average price, per Mcf (excluding gas products)(3)

$
2.79

$
4.77

$
3.40

$
4.86Crude oil and condensate revenues

$
2,109,957

$
3,689,442

$
6,502,663

$
9,408,150Natural gas and gas products revenues


132,935


393,022


601,193


875,301Production expenses


(936,358
)

(1,330,489
)

(2,841,709
)

(4,668,967
)Capital expenditures


(229
)

(18,031
)

(933
)

(175,608
)InterestUndistributed net loss (income)(4)


(1,306,304
)

(2,733,945
)

(4,261,214
)

(5,438,877
)Refund of (provision for) Special Cost Escrow











​
​
​
​
​
​
​
​
​
​
​
​
​
​Net Proceeds











Royalty interest


X15
%

X15
%

X15
%

X15
%​
​
​
​
​
​
​
​
​
​
​
​
​
​Partnership share











Trust interest


x99.99
%

x99.99
%

x99.99
%

x99.99
%​
​
​
​
​
​
​
​
​
​
​
​
​
​Trust share of Royalty Income(5)

$


$


$


$
​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​​
​
​
​
​
​
​
​
​
​
​
​
​
​


31

---






(1)Amounts
are based on production for the three- and nine-month period ended July 31 of each year, respectively, and include the results of the
adjustments for Eugene Island 339 and Eugene Island 342.(2)Excluding
the adjustments, the average price for the three months ended September 30, 2015 and 2014 was $60.75 and $103.13, respectively, and for the
nine months ended September 30, 2015 and 2014 was $62.10 and $101.87, respectively.(3)Excluding
the adjustments, the average price for the three months ended September 30, 2015 and 2014 was $2.79 and $4.82, respectively, and for the
nine months ended September 30, 2015 and 2014 was $3.35 and $4.90, respectively.(4)Undistributed
net loss represents the amount of development and production costs associated with the Royalty that exceed the proceeds of production from the
Royalty Properties during the period. An undistributed net loss is carried forward and offset, in future periods, by positive proceeds earned by the related Working Interest Owner(s). The Trust will
not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus applicable accrued interest. Undistributed net income represents positive Net Proceeds,
generated during the respective period, but not distributed by the Working Interest Owners.(5)See
"Trustee's Discussion and Analysis of Financial Condition and Results of OperationsLiquidity and Capital Resources" and Note 4 to
the Notes to the Condensed Financial Statements under Item 1 of Part I of this Form 10-Q for a discussion regarding uncertainty of distributions.


Critical Accounting Policies

Disclosure of critical accounting policies and the more significant judgments and estimates used in the preparation of the Trust's
financial statements are included in Item 7 of the 2014 10-K. There have been no significant changes to the critical accounting policies during the nine months ended September 30, 2015.

New Accounting Pronouncements

There were no accounting pronouncements issued during the three months ended September 30, 2015 applicable to the Trust or its
condensed financial statements.

Off-Balance Sheet Arrangements

The Trust has no off-balance sheet arrangements. The Trust has not guaranteed the debt of any other party, nor does the Trust have any
other arrangements or relationships with other entities that could potentially result in unconsolidated debt, losses or contingent obligations.

Item 3.    Quantitative and Qualitative Disclosures About Market Risk.

The only assets of and sources of income to the Trust are cash and the Trust's interest in the Partnership, which is the holder of the
Royalty. Consequently, the Trust is exposed to market risk associated with the Royalty from fluctuations in oil and gas prices. Reference is also made to Note 2 of the Notes to Condensed
Financial Statements included in Item 1 of this Form 10-Q.

The
Trust has in the past and is currently expected to continue to borrow money to pay expenses of the Trust. Additionally, if development and production costs of the Royalty exceed the
proceeds of

32

---



production
from the Royalty Properties, the Trust will not receive Net Proceeds until future proceeds from production exceed the total of the excess costs plus accrued interest, at a rate equal to
one-fourth of (i) one-half of one percent plus (ii) the median between the prime interest rate at the end of a quarterly period in which there are excess costs and the prime interest
rate at the end of the preceding quarterly period, during the deficit period. Consequently, the Trust will be exposed to interest rate market risk should it borrow money to pay expenses and to the
extent that development and production costs of the Royalty exceed the proceeds of production from the Royalty Properties.

Item 4.    Controls and Procedures.

Evaluation of disclosure controls and procedures.The Corporate Trustee maintains disclosure controls and procedures designed to ensure
that
information required to be disclosed by the Trust in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within
the time periods specified in the SEC's rules and regulations. Disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed by the
Trust is accumulated and communicated by Chevron, as the Managing General Partner of the Partnership, and the Working Interest Owners to the Corporate Trustee of the Trust, and its employees who
participate in the preparation of the Trust's periodic reports as appropriate to allow timely decisions regarding required disclosure.

As
of the end of the period covered by this report, the Corporate Trustee carried out an evaluation of the Trust's disclosure controls and procedures. Michael J. Ulrich, as Trust Officer
of the Corporate Trustee, has concluded that the disclosure controls and procedures of the Trust are effective.

Due
to the contractual arrangements of (i) the Trust Agreement, (ii) the Partnership Agreement and (iii) the rights of the Partnership under the Conveyance regarding
information furnished by the Working Interest Owners, the Trustees rely on (A) information provided by the Working Interest Owners,
including historical operating data, plans for future operating and capital expenditures, reserve information and information relating to projected production, (B) information from the Managing
General Partner of the Partnership, including information that is collected from the Working Interest Owners, and (C) conclusions and reports regarding reserves by the Trust's independent
reserve engineers. See Item 1A. Risk Factors "The Trustees and the Unit holders have no control over the operation or development of the Royalty Properties and have little
influence over operation or development" and "The Trustees rely upon the Working Interest Owners and Managing General Partner for information regarding the Royalty Properties" in the 2014
Form 10-K for a description of certain risks relating to these arrangements and reliance on and applicable adjustments to operating information when reported by the Working Interest Owners to
the Corporate Trustee and recorded in the Trust's results of operation.

Changes in Internal Control Over Financial Reporting.During the three months ended September 30, 2015, there has been no change
in the
Trust's internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, the Trust's internal control over financial reporting. The Corporate
Trustee notes for purposes of clarification that it has no authority over, and makes no statement concerning, the internal control over financial reporting of the Working Interest Owners or the
Managing General Partner of the Partnership.

33

---



PART IIOTHER INFORMATION

Item 1.    Legal Proceedings.

On July 10, 2014, the Trustees filed a Petition for Modification and Termination of the Trust (the "Petition") with the Probate
Court of Travis County, Texas (the "Court"). The Petition requests the Court to modify the Trust Agreement to (1) allow for the termination of the Trust by a court order, and (2) allow
the Trustees, as necessary to fulfill the purposes of the Trust and without unitholder approval to (a) sell all or any portion of the Trust's interests in the Partnership or any other assets of
the Trust, (b) exercise their rights to dissolve the Partnership, or (c) cause the Partnership to sell the Royalty. The goals in filing such probate proceeding are to permit the Trustees
to direct the Partnership to sell the Royalty; to distribute the net proceeds resulting from such sale, after payment of the Trust's liabilities, to the Trust's unitholders; and, to, thereafter
terminate the Partnership and the Trust. The Trust has completed the process of serving the Petition on the Trust's Unit holders. The Court appointed an attorney ad litem to represent any Unit holders
that were not personally served. The Court appointed attorney ad litem filed a Counterclaim against the Trust on November 16, 2015 requesting (1) an order to sell all of the Royalty
Interests, and (2) an accounting of the general and administrative expenses of the Trust from 2008 through the present. The trial is currently set for January 15, 2016; however, it is
possible that the Counterclaim filed by the attorney ad litem could result in a delay. There can be no assurances whether the Court will grant the requested relief and, if such relief is granted, when
such actions will be completed.

Item 1A.    Risk Factors.

There have not been any material changes from the risk factors previously disclosed in the Trust's response to Item 1A. to
Part 1 of the 2014 10-K.

34

---





Item 6.    Exhibits.

(Asterisk indicates exhibit previously filed with the Securities and Exchange Commission and incorporated herein by reference.)

SEC File or
Registration
Number

Exhibit
Number4(a)
*


Trust Agreement dated as of January 1, 1983, among Tenneco Offshore Company, Inc., Texas Commerce Bank National Association, as corporate trustee, and Horace C. Bailey, Joseph C. Broadus and F. Arnold Daum, as
individual trustees (Exhibit 4(a) to Form 10-K for the year ended December 31, 1992 of TEL Offshore Trust)


0-06910


4(a
)4(b)
*


Agreement of General Partnership of TEL Offshore Trust Partnership between Tenneco Oil Company and the TEL Offshore Trust, dated January 1, 1983 (Exhibit 4(b) to Form 10-K for year ended December 31,
1992 of TEL Offshore Trust)


0-06910


4(b
)4(c)
*


Conveyance of Overriding Royalty Interests from Exploration I to the Partnership (Exhibit 4(c) to Form 10-K for year ended December 31, 1992 of TEL Offshore Trust)


0-06910


4(c
)4(d)
*


Amendments to TEL Offshore Trust Agreement, dated December 7, 1984 (Exhibit 4(d) to Form 10- K for year ended December 31, 1992 of TEL Offshore Trust)


0-06910


4(d
)4(e)
*


Amendment to the Agreement of General Partnership of TEL Offshore Trust Partnership, effective as of January 1, 1983 (Exhibit 4(e) to Form 10-K for the year ended December 31, 1992 of TEL Offshore
Trust)


0-06910


4(e
)10(a)
*


Purchase Agreement, dated as of December 7, 1984 by and between Tenneco Oil Company and Tenneco Offshore II Company (Exhibit 10(a) to Form 10-K for year ended December 31, 1992 of TEL Offshore
Trust)


0-06910


10(a
)10(b)
*


Consent Agreement, dated November 16, 1988, between TEL Offshore Trust and Tenneco Oil Company (Exhibit 10(b) to Form 10-K for year ended December 31, 1988 of TEL Offshore Trust)


0-06910


10(b
)10(c)
*


Assignment and Assumption Agreement, dated November 17, 1988, between Tenneco Oil Company and TOC- Gulf of Mexico Inc. (Exhibit 10(c) to Form 10-K for year ended December 31, 1988 of TEL Offshore
Trust)


0-06910


10(c
)


35

---



SEC File or
Registration
Number

Exhibit
Number10(d)
*


Gas Purchase and Sales Agreement Effective September 1, 1993 between Tennessee Gas Pipeline Company and Chevron U.S.A. Production Company (Exhibit 10(d) to Form 10-K for year ended December 31, 1993 of
TEL Offshore Trust)


0-06910


10(d
)31



Certification furnished pursuant to Section 302 of the Sarbanes-Oxley Act of 200232



Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002


36

---





SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its
behalf by the undersigned, thereunto duly authorized.

TEL OFFSHORE TRUSTBy:

The Bank of New York Mellon
Trust Company, N.A.
Corporate TrusteeBy:

/s/ MICHAEL J. ULRICH Michael J. Ulrich Vice President


Date:
November 16, 2015

The
Registrant, TEL Offshore Trust, has no principal executive officer, principal financial officer, board of directors or persons performing similar functions. Accordingly, no
additional signatures are available and none have been provided.

37

---



QuickLinks